Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer; such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms an area or reservoir in which hydrocarbons will collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then can flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.
Once the casing is cemented in place, it is perforated at the level of the oil-bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.
This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes telescoped wholly or partially within other tubes.
Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons can flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the fluid along with gelling agents to create a slurry. The slurry is injected into the formation, fracturing it and creating flow paths to the well. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation typically will be fractured in many different locations or zones, but rarely, if ever, will it be fractured all at once. A liner first will be installed in the well. The liner will incorporate valves, or the liner may be perforated in a first zone near the bottom of the well. Fluids then are pumped into the well to fracture the formation in the vicinity of the bottom perforations. After the initial zone is fractured, a plug is installed in the liner at a point above the fractured zone. The liner is perforated again, this time in a second zone located above the plug. That process is repeated for zones further up the formation until the formation has been completely fractured.
Once the well is fractured, the large quantities of water and sand that were injected into the formation eventually must be allowed to flow out of the well. The water and sand will be separated from hydrocarbons produced by the well to protect downstream equipment from damage and corrosion. The production stream also may require additional processing to neutralize corrosive agents in the stream.
Systems for successfully completing a fracturing operation, therefore, are extensive and complex, as may be appreciated from FIG. 1. Water from tanks 1 and gelling agents dispensed by a chemical unit 2 are mixed in a hydration unit 3. The discharge from hydration unit 3, along with sand carried on conveyors 4 from sand tanks 5 is fed into a blending unit 6. Blender 6 mixes the gelled water and sand into a slurry. The slurry is discharged through low-pressure hoses 7 which convey it into two or more low-pressure lines 8 in a frac manifold 9. The low-pressure lines 8 in frac manifold 9 feed the slurry to an array of pumps 10, perhaps as many as a dozen or more, through low-pressure “suction” hoses 11.
Pumps 10 take the slurry and discharge it at high pressure through individual high-pressure “discharge” lines 12 into two or more high-pressure lines or “missiles” 13 on frac manifold 9. Missiles 13 flow together, i.e., they are manifolded on frac manifold 9. Several high-pressure flow lines 14 run from the manifolded missiles 13 to a “goat head” 15. Goat head 15 delivers the slurry into a “zipper” manifold 16 (also referred to by some as a “frac manifold”). Zipper manifold 16 allows the slurry to be selectively diverted to, for example, one of two well heads 17. Once fracturing is complete, flow back from the fracturing operation discharges into a flowback manifold 18 which leads into flowback tanks 19.
Frac systems are viewed as having “low-pressure” and “high-pressure” sides or, more simply, as having low sides and high sides. The low side includes the components upstream of the inlet of pumps 10, e.g., water tanks 1, hydration unit 3, blending unit 6, and the low-pressure lines 8 of frac manifold 9, which operate under relatively low pressures. The high side includes all the components downstream of the discharge outlets of pumps 10, e.g., the high-pressure missiles 13 of frac manifold 9 and flow lines 14 running to goat head 15, which operate under relatively high pressures.
The flow lines and units making up the high-side of a frac system, such as pump discharge lines 12 and flow line 14, typically are assembled from a large number of individual components often referred to as “frac iron,” “flow iron,” or “ground iron.” Such components include straight steel pipe, fittings for splitting, combining, or changing direction of a line, gauges and other monitoring equipment, and valves and other control devices. Flow iron components are fabricated from heavy, high tensile steel and are quite rugged. They may be rated for high-pressure service up to 20,000 psi.
Nevertheless, flowline components can suffer shortened service life or failure due to the harsh conditions to which they are exposed. Not only are fluids pumped through the system at very high pressure and flow rates, but the fluid is abrasive and corrosive. Components may suffer relatively rapid erosion. The high flow rates and pressures also create vibrations through the system and exacerbate and concentrate stress on the components. The resulting strain may create fractures in the components which can propagate and lead to failure, especially in areas weakened by erosion and corrosion.
Frac jobs also have become more extensive, both in terms of the pressures required to fracture a formation and the time required to complete all stages of an operation. Prior to horizontal drilling, a typical vertical well might require fracturing in only one, two or three zones at pressures usually well below 10,000 psi. Fracturing a horizontal well, however, may require fracturing in 20 or more zones. Horizontal wells in shale formations such as the Eagle Ford shale in South Texas typically require fracturing pressures of at least 9,000 psi and 6 to 8 hours or more of pumping. Horizontal wells in the Haynesville shale in northeast Texas and northwest Louisiana require pressures around 13,500 psi. Pumping may continue near continuously—at flow rates of 2 to 3 thousand gallons per minute (gpm)—for several days before fracturing is complete.
Any failure of flowline components on site may interrupt fracturing, potentially reducing its effectiveness and inevitably increasing the amount of time required to complete the operation. Moreover, if a component fails, large quantities of fluid can be ejected at very high pressures, causing the components to move violently and potentially injure workers. Flowline components must be certified and periodically inspected and recertified, but not all damage to or weakening of the components may be detected. Fatigue stress and microscopic fracturing is difficult to detect and can lead to catastrophic failure.
Consequently, and especially in respect to the high-side of a system, if operating pressures exceed the pressure rating of a flow line at any point, operators typically will simply scrap any component that was exposed to above-rated pressures. That can add up to significant cost. Having been designed and manufactured for such harsh operating conditions, flow iron components are quite expensive, especially components rated for high pressures. Operators, therefore, invariably incorporate valves for releasing pressure from a line before the rated pressure is exceeded.
One general approach is use an automatically controlled valve which can be opened and shut, such as a needle, globe, plug, or gate valve. The valve is tapped into the line, as is a transducer or other sensor capable of detecting pressure. The pressure sensor is connected to a controller which will open the valve if excess pressure is detected. Once excess pressure has bled off and rated pressures are restored, the controller will shut the valve again.
Pressure transducers are capable of measuring pressures with accuracy and precision. Thus, automatic valves can reliably open a valve when pressures in the line actually exceed rated pressures, but will not open when rated pressures are not exceeded. On the other hand, valves that can be cycled open and closed, and especially their valve seats, are more susceptible to wear and damage. Thus, once opened, they may not fully set and seal, and effectively shut the valve again.
Self-actuating valves, essentially check valves, also are employed. A valve element, such as a needle or globe element, is exposed to pressure in a flow line, but is held against a seat by a spring or compressed gas. Such valves, however, are extremely difficult to calibrate. Thus, they frequently will actuate above or below their rated pressures. They also are subject to wear and damage which can prevent them from setting and sealing once they have been in service for a period of time.
Another general approach is to use valves with a sacrificial closure, most commonly a burst valve. Such valves are not opened and closed in the common sense of the words. The sacrificial closure is intended for one use only. A burst disc, for example, may be used to shut off a passage through the valve. The burst disc is designed to burst when a specified pressure is exceeded, thus opening the passage and allowing the line to bleed off fluid. Once the disc has burst, a burst valve will remain “open” until a new disc is installed.
Valves with sacrificial closures also can provide accurate and precise release of excessive pressures. The degree of control, however, depends on how reliably and consistently the burst disc or other closure fails. Burst discs in particular may be manufactured to precise specifications with very close tolerances, but are relatively expensive. Lower tolerance burst discs are significantly cheaper. If used, however, they, must be rated well below a desired threshold pressure to ensure that they fail when required. Necessarily, then, they may frequently burst below rated pressures and cause unnecessary disruption of the fracturing process. Moreover, burst discs have a shelf life beyond which they will not perform to specification, and the higher the tolerance the shorter the shelf life.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved pressure release valves and methods for protecting high-pressure flowlines from excessive pressure. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.